Reducing refrigeration duty on a refrigeration unit in a gas processing system

ABSTRACT

A liquefaction process configured to facilitate thermal transfer in a heat exchanger during liquefaction of a natural gas feedstock. The liquefaction process can include compressing a process stream to a first pressure, the process stream comprising predominantly methane, cooling the process stream to a first temperature, expanding the process stream from the first pressure to a second pressure that is less than the first pressure, bleeding-off a first product from the process stream at the second pressure, and conditioning the first product for storage as liquid natural gas (LNG).

BACKGROUND

Liquefying natural gas can facilitate transport and storage of hydrocarbons and related material. Generally, the processes greatly reduce the volume of gas. The resulting liquid is well-suited to transit long distances through pipelines and infrastructure. It is particularly economical for transport overseas and/or to areas that are not accessible by such pipeline infrastructure.

SUMMARY

The subject matter of this disclosure relates generally to liquefaction processes. The embodiments address refrigeration requirements of a heat exchanger (or “cold box”) necessary to liquefy an incoming hydrocarbon feed to a liquefied product. In one application, the embodiments incorporate a fluid circuit to liquefy a natural gas feed to liquid natural gas (LNG).

As noted more below, the improvements afford the embodiments herein with many capabilities and/or advantages. The fluid circuit can take on some of the duty cycle of a primary refrigeration unit that cool the heat exchanger. This feature can permit the embodiments to expand or increase production of LNG product to levels that would normally outstrip operation of certain equipment (e.g., compressors) in the liquefaction system. Use of the embodiments can allow the liquefaction system to increase production levels by approximately 80% using the default or initial configuration or, for purposes of example, to increase production from 450,000 gpd to approximately 800,000 gpd. Moreover, liquefaction systems that supplement cooling of the heat exchanger with the embodiments can operate at or above efficiencies as compared to other auxiliary refrigeration systems (e.g., propane pre-cooling), particularly at production levels at less than 700,000 gpd.

These production improvements come at limited, if any, capital and/or operating expenses. Liquefaction systems that incorporate the fluid circuit of the embodiments herein require little design changes to the primary refrigeration system. This feature can forgo the need to modify refrigerants and/or equipment, lines, controls, and/or other components of the primary refrigeration system.

The embodiments may find use in many different types of processing facilities. These facilities may be found onshore and/or offshore. In one application, the embodiments can incorporate into and/or as part of processing facilities that reside on land, typically on (or near) shore. These processing facilities can process natural gas feedstock from production facilitates found both onshore and offshore. Offshore production facilitates use pipelines to transport feedstock extracted from gas fields and/or gas-laden oil-rich fields, often from deep sea wells, to the processing facilitates. For LNG processing, the processing facility can turn the feedstock to liquid using suitably configured refrigeration equipment or “trains.” In other applications, the embodiments can incorporate into production facilities on board a ship (or like floating vessel), also known as a floating liquefied natural gas (FLNG) facility.

BRIEF DESCRIPTION OF THE DRAWINGS

Reference is now made briefly to the accompanying drawings, in which:

FIG. 1 depicts a flow diagram of an exemplary embodiment of a process to liquefy a hydrocarbon feedstock to liquid natural gas (LNG) for storage;

FIG. 2 depicts a flow diagram of an example of the process of FIG. 1;

FIG. 3 depicts a schematic diagram of an exemplary embodiment of a system that can liquefy an incoming hydrocarbon feedstock to a product that meets specifications for liquefaction to liquid natural gas (LNG);

FIG. 4 depicts a schematic diagram of an example of the system of FIG. 3 that can accommodate an incoming hydrocarbon feedstock with a high level of impurities;

FIG. 5 depicts a schematic diagram of a first configuration of components to form a fluid circuit in an example of the system of FIG. 3;

FIG. 6 depicts a schematic diagram of a second configuration of components to form a fluid circuit in an example of the system of FIG. 3;

FIG. 7 depicts a schematic diagram of an example of the system of FIG. 3 that can accommodate an incoming hydrocarbon feedstock with a high level of impurities;

FIG. 8 depicts a schematic diagram of an example of the system of FIG. 7; and

FIG. 9 a schematic diagram of an example of the system of FIG. 7.

Where applicable like reference characters designate identical or corresponding components and units throughout the several views, which are not to scale unless otherwise indicated. The embodiments disclosed herein may include elements that appear in one or more of the several views or in combinations of the several views. Moreover, methods are exemplary only and may be modified by, for example, reordering, adding, removing, and/or altering the individual stages.

DETAILED DESCRIPTION

FIGS. 1 and 2 illustrate flow diagrams of an exemplary embodiment of a process 10 to liquefy an incoming hydrocarbon feedstock. As shown in FIG. 1, the embodiments may include, at stage 12, receiving a feedstock and, at stage 14, forming a process stream from the feedstock, the process stream comprising predominantly methane in a concentration of 92% or greater. The process 10 can also include, at stage 16, compressing the process stream to a first pressure and, at stage, 18, cooling the process stream to a first temperature. The process 10 can further include, at stage 20, expanding the process stream from the first pressure to a second pressure that is less than the first pressure. The process 10 can include, at stage 22, bleeding-off a first stream from the process stream at the second pressure and, at stage 24, conditioning the first stream for storage as liquid natural gas (LNG). In one implementation, the process 10 can include, at stage 26, compressing the process stream from the second pressure to an intermediate pressure that is between the first pressure and the second pressure. The process 10 can then continue to further compress the process stream at stage 16.

In the example of FIG. 2, the process 10 can include, at stage 14, various stages to accommodate an incoming hydrocarbon feedstock with a high level of impurities. The process 10 can include, at stage 28, separating the feedstock into a first stream and a first bottom product. The process 10 can also include, at stage 30, introducing the first stream into the process stream at the intermediate pressure. In one implementation, the process 10 can include, at stage 32, distilling the first bottom product to form a second stream and a second bottom product and, at stage 34, introducing the second stream into the process stream at the second pressure. The process 10 can further include, at stage 36, conditioning the second bottom product to form a liquid petroleum gas (LPG).

FIG. 3 illustrates a schematic diagram of an exemplary embodiment of a gas processing system 100 (also, “system 100”) for use to process natural gas and like hydrocarbon materials. The system 100 may include an expansion unit 102 and a refrigeration unit 104, each coupled with a heat exchanger 106. Examples of the heat exchanger 106 or “cold box” can feature brazed aluminum fins (“plate-fin exchanger”) and/or coils (“coil wound exchanger). These devices can facilitate thermal transfer by indirect contact between fluids. The fluids may include a refrigerant 108 that the refrigeration unit 104 circulates through the heat exchanger 106. Examples of the refrigerant 108 can have a composition comprising one or more constituent components including light hydrocarbons (e.g., methane, ethane, propane, etc.) and/or nitrogen. In one implementation, the composition is consistent with a “mixed” refrigerant cycle.

The expansion unit 102 can be configured to reduce the duty cycle on the refrigeration unit 104 necessary to cool the heat exchanger 106. These configurations can be used in lieu of auxiliary or supplementary refrigeration units (e.g., propane coolers) that may provide supplemental cooling and/or pre-cooling of fluids in the heat exchanger 106. The expansion unit 102 can include a fluid circuit 110 that circulates fluid through the heat exchanger 106. For clarity, the fluid that circulates in the fluid circuit 110 is identified as a process stream 112. Examples of the process stream 112 can have a composition that is predominantly methane in liquid and/or vapor forms. In one implementation, the fluid circuit 110 can be configured to bleed-off a first product 114 from the process stream 112. The first product 114 may meet specifications for liquid natural gas (LNG). The system 100 can direct the first product 114 from the heat exchanger 106 to a storage facility 116 or other post-liquefaction facility, as desired. Notably, use of the expansion unit 102 can expand the range of production levels of LNG product (e.g., the first product 114) on the system 100. It is reasonable that the system 100 can expand production levels of LNG product from approximately 450,000 gpd to approximately 800,000 gpd.

The system 100 can operate on incoming natural gas and like hydrocarbon streams. As shown in FIG. 1, the fluid circuit 110 may receive these streams as a feedstock 118 from a source 120. The source 120 may include pre-treatment equipment that process natural gas from production facilities (e.g., well-head, pipeline, etc.). These processes can result in “dry sweet gas” with a composition that is predominantly methane (e.g., in a concentration of 84% (840,000 ppmV) or greater) and with a concentration of water that is less than 0.0001% (1 ppmV). For compositions that lack significant levels of impurities, the fluid circuit 110 can be configured to directly circulate the feedstock 118 as the process stream 112. These compositions may, for example, have concentrations of methane that are 98% (980,000 ppmV) or greater. However, at least one benefit of the expansion unit 102 is that it can be configured in manner that can remove impurities from the feedstock 118 prior to, or upstream of, the fluid circuit 110.

FIG. 4 illustrates an example of the system 100 that can handle compositions of the feedstock 118 with higher levels of impurities. At a high level, the expansion unit 102 may include a pre-processing unit 122 upstream of the fluid circuit 110. The pre-processing unit 122 can receive the feedstock 118 via pipeline and/or other modality from the source 120. In one implementation, the pre-processing unit 122 can form a feedstream 124 and a second product 126. The system 100 can direct the feedstream 124 into fluid circuit 110 for use as the process stream 112. The second product 126 can be a derivative product that is useful for fuel. Such derivative products may have a composition of hydrocarbon gases (e.g., propane, butane, etc.) and/or like constituent components. The composition may be consistent with a liquid petroleum gas (LPG) product. The system 100 may be configured to direct this LPG product to a collateral system 128 for further processing and/or storage, e.g., in a tank.

FIG. 5 depicts a first configuration of components to implement the fluid circuit 110. This first configuration forms an open loop to circulate the process stream 112 through the heat exchanger 106. The open loop includes a turbo-machine 130, preferably with a turbo-compressor 132 that is configured to operate in response to work from a turbo-expander 134. The turbo-compressor 132 can have an inlet 136 and an outlet 138 that couple with the heat exchanger 106 and with a methane compressor 140, respectively. As also shown in FIG. 6, the turbo-expander 134 can have an inlet 142 and an outlet 144. The inlet 142 can couple with the heat exchanger 106. The outlet 144 can couple with a first separator unit 146, which itself couples with the heat exchanger 106.

Starting at the methane compressor 140, the fluid circuit 110 can use the feedstock 118 from the source 120 without any upstream processing. This first configuration may be useful with incoming natural gas with low levels of impurities. In one implementation, incoming feedstock 118 is introduced into the methane compressor 140, typically at a temperature of from approximately 80° F. to approximately 120° F. The methane compressor 140 can be configured to accommodate in-flow pressures for the feedstock 118 of approximately 450 psig and larger. However, this disclosure does consider that the methane compressor 140 and the fluid circuit 110, generally, can be configured for use of the system 100 across a wide range of applications to accommodate in-flow pressures that vary in accordance with the source 120, as necessary. Such configurations may vary the location(s) at which the incoming feedstock 118 is introduced to the process stream 112 in the methane compressor 140.

The methane compressor 140 can be configured to modify temperature and pressure of the process stream 112. These configurations may flow the process stream 112 through one or more cooling devices (e.g., air coolers). In this way, the process stream 112 can exit the methane compressor 140 (at 148) at a temperature of approximately 20° F. above ambient temperature that prevails at the location of the system 100. In one implementation, the methane compressor 140 may also pressurize the process stream 112 so that the process stream 112 (at 148) is at a pressure of 1200 psig. The pressure may be selected based on construction considerations (e.g., flange ratings) for the fluid circuit 110; for example, operating the system 100 at pressures not in excess of 1200 psig will require flanges rated at class 600 lbs. or less, thus potentially providing a considerable cost savings. Other temperatures and pressures for the process stream 112 (at 148) may be useful, as well.

The system 100 may direct the process stream 112 across a first pass of the heat exchanger 106 to further reduce the temperature. The heat exchanger 106 can be configured so that the process stream 112 enters the inlet 142 of the turbo-expander 134 at approximately −90° F. and/or otherwise in a range of from approximately −70° F. to approximately −110° F. In turn, the turbo-expander 134 can reduce the pressure of the process stream 112. For example, the process stream 112 can exit the turbo-expander 134 (at 150) as a mixed phase effluent (e.g., liquid and vapor). The process stream 112 (at 150) can have an outlet pressure that ensures efficient operation of the system 100. Examples of the turbo-expander 134 can operate so that outlet pressure maintains an expansion ratio with the pressure of the process steam 112 (at 148) of from three and four; however, this disclosure contemplates that the outlet pressure may maintain the expansion ratio in range of from three and ten, as desired. In one example, the outlet pressure can be in a range of from approximately 285 psig to approximately 385 psig to accommodate operation of the methane compressor 140 to pressurize the process stream 112 to 1200 psig.

The fluid circuit 110 directs the process stream 112 from the turbo-expander 134 to the first separator unit 146. Processing of the process stream 112 in the first separator unit 146 may result in a bottom product 152 and a top product 154. The products 152, 154 exit the bottom and top of the first separator unit 146 in liquid and vapor form, respectively. The liquid bottom product 152 transits a second pass of the heat exchanger 106. This second pass conditions the liquid bottom product 152, typically reducing the temperature to form the first product 114 at and/or near temperatures for storage at the storage facility 116. The storage temperatures may be in a range of from approximately −250° F. to approximately −270° F.

The vapor top product 154 forms the process stream 112 that continues to circulate through the fluid circuit 110. In one implementation, the fluid circuit 110 directs the process stream 112 through a third pass of the heat exchanger 106. This third pass can decrease the temperature of the process stream 112, typically by expelling thermal energy to fluid in one of the other passes in the heat exchanger 106. The system 100 can be configured so that the temperature of the process stream 112 at the inlet 136 of the turbo-compressor 132 is in a range of from approximately 80° F. to approximately 120° F.

The turbo-compressor 132 can pressurize the process stream 112. In one implementation, the turbo-compressor 132 discharges the process stream 112 (at 156) at an intermediate pressure, preferably between the discharge (or first) pressure (at 148) of the methane compressor 140 and the discharge (or second) pressure (at 150) of the turbo-expander 134. This intermediate pressure may be a range from approximately 400 psig to approximately 600 psig. The fluid circuit 110 can direct the process stream 112 at the intermediate pressure back to the methane compressor 140. As noted above, the fluid circuit 110 can introduce the feedstock 118 into the process stream 112 so that the resulting mixed stream exits the methane compressor 140 (at 148).

FIG. 6 depicts a second configuration of components to implement the fluid circuit 110. The methane compressor 140 has a compression circuit 158 with a first end 160 and a second end 162, one each coupled with the turbo-compressor 132 and the heat exchanger 106, respectively. At a high level, the compression circuit 158 may be configured to increase the pressure and without increasing the temperature of the process stream 112 from the first end 160 to the second end 162. Such function may utilize various components (e.g., coolers, compressors, etc.). In one implementation, the compression circuit 158 may include one or more coolers (e.g., a first cooler 164, a second cooler 166, and a third cooler 168). The coolers 164, 166, 168 may be air-cooled, although this disclosure does not limit selection to any particular type or variation for these devices. The compression circuit 158 may also include one or more compressors (e.g., a first compressor 170 and a second compressor 172). The compressors 170, 172 may be disposed between adjacent coolers 164, 166, 168 to maintain and/or raise the pressure of process stream 112 (at 148) at the temperature and pressure noted herein.

FIG. 7 depicts an example of the pre-processing unit 122 for use with the system 100. In one implementation, the pre-processing unit 122 may include a second separator unit 174 that couples with a demethanizer unit 176. The second separator unit 174 can remove heavy hydrocarbons from the feedstock 118. This feature is useful to avoid problems in the system 100 due to freeze out of impurities downstream and/or in storage, e.g., in the storage facility 116. The demethanizer unit 176 can recover light hydrocarbons (e.g., methane). Each of the units 174, 176 may couple separately with the fluid circuit 110 at one or more locations (e.g., a first location 178 and a second location 180). At the first location 178, the second separator unit 174 couples with the compression circuit 158 of the methane compressor 140. At the second location 180, the demethanizer unit 176 couples between the turbo-expander 134 and the first separator unit 146.

The pre-processing unit 122 can remove impurities from the feedstock 118 upstream the fluid circuit 110. In use, the feedstock 118 can transit a fourth pass of the heat exchanger 106. This fourth pass can lower the temperature of the feedstock 118 to a range of from approximately −80° F. to approximately −110° F. The cooled feedstock 118 enters the second separator unit 174 to remove impurities (e.g., heavy hydrocarbons). In one implementation, the second separator unit 174 is configured to form a first stream 182 and a first bottom product 184, one each that exits the bottom and top of the second separator unit 174 in vapor and liquid form, respectively. The vapor first stream 182 comprises predominantly methane vapor, typically in a concentration of from approximately 92% (920,000 ppmV) to approximately 97% (970,000 ppmV). The system 100 directs the vapor first stream 182 through a fifth pass of the heat exchanger 106 and into the compression circuit 158 at the first location 178. This fifth pass can raise the temperature of the vapor first stream 182 to a range of from approximately 80° F. to approximately 120° F.

The system 100 directs the first bottom product 184 to the demethanizer unit 176. In one implementation, the demethanizer unit 176 is configured to form a second stream 186 and a second bottom product 188, each exiting the bottom and top of the demethanizer unit 176 in liquid and vapor form, respectively. The vapor second stream 186 comprises predominantly methane vapor, typically in a concentration of from approximately 92% (920,000 ppmV) to approximately 97% (970,000 ppmV). The system 100 can direct vapor second stream 186 to enter the fluid circuit 110 at the second location 180, effectively by-passing the heat exchanger 106. The second bottom product 188 can form the second product 126 that is directed to the collateral system 128 and/or processing found further downstream of the system 100 at the facility.

FIG. 8 depicts an example of the system 100 with additional components that may be useful to modulate pressure (and/or temperature) of fluid. The system 100 may include one or more expansion valves (e.g., a first expansion valve 190, a second expansion valve 192, and a third expansion valve 194). J-T valves and like devices may be suitable for use as the valves 190, 192, 194. The pre-processing unit 122 may incorporate a reboiler 196 to boil the second bottom product 188 from the demethanizer unit 176. Boiling results in vapor that is directed back into the demethanizer unit 176.

FIG. 9 illustrates an example of the system 100 also with additional components to accommodate certain production levels and/or other process changes as necessary. The system 100 may include a third separator unit 198 upstream of the turbo-expander 134 and interposed between the heat exchanger 106. Vapor from the third separator unit 198 enters the turbo-expander 134. Liquids from the third separator unit 198 are mixed with the effluent (at 150) from the turbo-expander 134, preferably upstream to the first separator unit 146.

The third separator unit 198 may be useful to prevent mixed phase feed that may occur at certain production levels at which temperatures of influent into the turbo-expander 134 may drop below the bubble point. This embodiment modifies the process so that a portion of vapor from the effluent (at 150) may be added to the influent generated from expansion to feed the heat exchanger 106. Other embodiments may use an expander recycle loop with a maximum pressure of approximately 700 psig and an expanded pressure of approximately 285 psig. At these pressures, vapor from the second separator unit 174 can be fed directly into the turbo-expander 134, by-passing the heat exchanger 106 to avoid any warming. This configuration may also forgo any compression of the vapor, as well.

In light of the foregoing, the embodiments compare favorably to other refrigeration techniques that might supplement any primary refrigeration as provided, for example, by mixed-refrigerant cycles discussed herein.

As used herein, an element or function recited in the singular and proceeded with the word “a” or “an” should be understood as not excluding plural said elements or functions, unless such exclusion is explicitly recited. Furthermore, references to “one embodiment” should not be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

This written description uses examples to disclose the embodiments, including the best mode, and also to enable any person skilled in the art to practice the embodiments, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the embodiments is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims. 

What is claimed is:
 1. A liquefaction process, comprising: compressing a process stream to a first pressure; cooling the process stream to a first temperature; expanding the process stream from the first pressure to a second pressure that is less than the first pressure; bleeding-off a first product from the process stream at the second pressure; and conditioning the first product for storage as liquid natural gas (LNG).
 2. The liquefaction process of claim 1, further comprising: compressing the process stream from the second pressure to an intermediate pressure that is between the first pressure and the second pressure.
 3. The liquefaction process of claim 1, wherein the process stream comprises liquid at the first pressure.
 4. The liquefaction process of claim 3, wherein the process stream comprises both vapor and liquid at the second pressure.
 5. The liquefaction process of claim 1, wherein the first pressure and the second pressure form a ratio of from 3 to
 10. 6. The liquefaction process of claim 1, further comprising: forming the process stream from a feedstock having a concentration of methane of 84% or greater.
 7. The liquefaction process of claim 6, further comprising: forming a first stream and a second stream from the feedstock, each comprising predominantly methane vapor, wherein the process stream comprises the first stream and the second stream.
 8. The liquefaction process of claim 7, further comprising: introducing the first stream into the process stream at the intermediate pressure.
 9. The liquefaction process of claim 7, further comprising: introducing the second stream into the process stream at the second pressure.
 10. The liquefaction process of claim 7, separating the feedstock into the first stream and a first bottom product; distilling the first bottom product to form the second stream and a second bottom product.
 11. A gas processing system, comprising: a heat exchanger; a fluid circuit coupled with the heat exchanger, the fluid circuit directing a process stream through the heat exchanger, wherein the fluid circuit is configured to: compress the process stream to a first pressure; pass the process stream through the heat exchanger at the first pressure; expand the process stream from the first pressure to a second pressure that is less than the first pressure; bleed-off a first stream from the process stream at the second pressure; and condition the first stream for storage as liquid natural gas (LNG).
 12. The gas processing system of claim 11, further comprising: a refrigeration unit coupled with the heat exchanger, wherein the refrigeration unit is configured to circulate a refrigerant through the heat exchanger.
 13. The gas processing system of claim 11, wherein the fluid circuit is configured to receive a feedstock and to circulate the feedstock as the process stream.
 14. The gas processing system of claim 13, further comprising: a pre-processing unit coupled with the fluid circuit and with the heat exchanger, the pre-processing unit having: a separator unit configured to receive the feedstock downstream of the heat exchanger; and a demethanizer coupled downstream of the separator unit, wherein the separator unit and the demethanizer are configured to form a first stream and a second stream, respectively, each comprising methane vapor, and wherein the process stream comprises the first stream and the second stream.
 15. A gas processing system, comprising: a heat exchanger; and a fluid circuit coupled with the heat exchanger, the fluid circuit configured to circulate a process stream through the heat exchanger, the fluid circuit comprising: a methane compressor coupled to the heat exchanger; a turbo-compressor interposed between the methane compressor and the heat exchanger; a turbo-expander coupled to the compressor and to the heat exchanger; and a first separator unit interposed between the turbo-expander and the heat exchanger.
 16. The gas processing system of claim 15, wherein the methane compressor is configured to pressurize the process stream to a first pressure and the turbo-expander is configured to expand the process stream to a second pressure that maintains a ratio between the first pressure and the second pressure in a range of from 3 to
 10. 17. The gas processing system of claim 16, wherein the turbo-compressor is configured to pressurize the process stream to an intermediate pressure that is between the first pressure and the second pressure.
 18. The gas processing system of claim 17, wherein the methane compressor is configured to pressurize the process stream from the intermediate pressure to the first pressure.
 19. The gas processing system of claim 15, further comprising: a second separator unit coupled to the heat exchanger and to the methane compressor; and a demethanizer coupled to the second separator and to the first separator unit.
 20. The gas processing system of claim 15, further comprising: an expansion valve disposed downstream of the first separator unit and the heat exchanger. 